Polymer Delivery in Well Treatment Applications

ABSTRACT

This invention relates to compositions and methods for treating subterranean formations, in particular, oilfield stimulation compositions and methods using water-in-water polymer emulsions to uniformly dissolve a rheologically active polymer, such as a thickener or friction reducer, in the treatment fluid. The emulsions have a low viscosity and are easily pumped for mixing into a treatment fluid, where upon dilution with an aqueous medium, the polymer is easily hydrated without forming fish-eyes. The partitioning agent in the water-in-water emulsion does not generally affect the rheology of the treatment fluid. The invention also relates to further processing of the emulsion by wet grinding, high shear mixing and/or heating to enhance the hydration rate in the preparation of the well treatment fluid.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims priority to and the benefit of U.S. 60/959,836,filed Jul. 17, 2007 and U.S. 61/054,277, filed May 19, 2008.

BACKGROUND OF THE INVENTION

This invention relates to methods for and fluids used in treating asubterranean formation. In particular, the invention relates to thepreparation and use of polymer delivery systems in the form ofconcentrated polymer suspensions useful for creating wellbore fluids andin methods of treating subterranean formations.

Various types of fluids are used in operations related to thedevelopment and completion of wells that penetrate subterraneanformations, and to the production of gaseous and liquid hydrocarbonsfrom natural reservoirs into such wells. These operations includeperforating subterranean formations, fracturing subterranean formations,modifying the permeability of subterranean formations, or controllingthe production of sand or water from subterranean formations. The fluidsemployed in these oilfield operations are known as drilling fluids,completion fluids, work-over fluids, packer fluids, fracturing fluids,stimulation fluids, conformance or permeability control fluids,consolidation fluids, and the like, and are collectively referred toherein as well treatment fluids.

Water-soluble polymers are frequently used for modifying the rheology,e.g. viscosification, proppant suspension, friction reduction, etc., ina number of subterranean formation treatment fluids, includingfracturing fluids, wellbore cleanout fluids, gravel pack fluids, and thelike. Creating these fluids often involves the steps of dispersing andhydrating polymers, such as guar, cellulose, and derivatives thereof,into a water stream. Hydration of polymers for oilfield applications isgenerally a slow process. The process normally involves at least a fewminutes of agitating the polymer, either a hydrocarbon slurry or drypolymer, with water in a flow path that contains different compartments.Although the process and hydration time has been shortened throughmultiple efforts in the past decades, it is still not as quick asdesired, i.e. reaching above 80% final fluid viscosity in less than 1 or1.5 minutes. The long hydration time requires the operation to have aspecific hydration unit, such as a Precision Continuous Mixer (PCM), ontop of a blending unit, such as a Programmable Optimum Density (POD)blender. The equipment and energy costs of this process are high.

Guar powders are generally obtained through a grinding process. The guarparticles generally have a twisted, plate-like structure that can beobserved under a microscope. Upon contact with water, the twistedstructures quickly unwind into layered structures that are more flat. Asthese structures are intercalated by absorbing more water, they swellunevenly into larger plates wherever they contact water. With unevenswelling between the layers, and assisted by some agitation, the layersexfoliate to almost individual sheets. The final step is to completelydissolve the swollen plate structures into individual molecular coils.In the hydration process, the swelling and exfoliation steps occurrapidly, usually in less than 10 seconds. The exfoliated platedissolution step is much slower and also depends on the degree ofagitation. The last step is the longest, usually accounting for about50-70% of the total time for the complete hydration process.

It is known that the smaller the polymer particles, the more surfacearea that can contact the aqueous phase and the faster the hydrationprocess. However, there have been several issues associated with the useof very small guar particles. Grinding the dry guar polymer can have adetrimental effect on the polymer performance because the grindingprocess can physically break the molecular chains and thus lower thepolymer molecular weight and therefore lower the ultimate gel viscosityyield. In addition, the smaller the particle size, the harder it is togrind in terms of grinder geometry, energy input, heat dissipationcontrol, and so on, which in turn lead to higher costs. Furthermore,when particles are small, they tend to form fish-eyes during hydration,where the outermost particles of an agglomerate quickly hydrate to athick gelatinous material that encapsulates the interior particles ofthe agglomerate and prevents the water from entering into the core forfurther hydration. Thus, the knowledge that finer particles willpotentially shorten hydration time has not led to effective improvementsto reduce the time to complete the hydration process.

Historically, oilfield polymer solutions were gelled in batch mixingprocesses by which dry polymer was mixed with water in tanks largeenough to hold all the fluid for a wellbore treatment. These batchtreatment processes had numerous limitations since gel once made coulddecompose from bacteria, and any gel not used at the wellsite waswasted. Additionally, batch mixing did not readily allow for changes ingel concentrations or loading during the course of a treatment.Accordingly, numerous technologies have been developed to allowcontinuous mix of polymer solutions at a wellsite. A successfultechnique for gelling an aqueous fluid must meet several criteria,including but not limited to allowing accurate metering of polymermaterial into a water stream, producing hydrated polymer fluids with aminimum amount of equipment, while also avoiding the formation offish-eyes when polymer particles contact water.

Continuous mix systems commonly in use typically use non-aqueousslurries or dry powder systems. Non-aqueous slurries comprise drypolymer suspended in an oil solvent, often diesel fuel which presentssome difficulties. To minimize the use of oil suspensions, servicecompanies have also developed dry systems in which dry polymer isdirectly mixed with water, but such systems can present another set ofdifficulties known to those of skill in the art. Some examples ofcomplicated polymer hydration equipment are disclosed in U.S. Pat. No.5,190,374, U.S. Pat. No. 5,382,411, U.S. Pat. No. 5,426,137 and US2004/0256106.

Similar difficulties are encountered when adding a friction reducer suchas acrylamide homopolymer or copolymer to low viscosity fracturingfluids known as slickwater fluids, which typically contain only 0.025 to0.2 weight percent of the friction reducer, in addition to otherconventional additives such as biocides, scale inhibitors, claystabilizers such as potassium chloride, trimethylammonium chloride orthe like. Friction reducers are available commercially in oil oroil-and-water emulsions. To reduce turbulent flow in the slickwaterfluid, the friction reducer must “flip” from the emulsion to rapidlydissolve in the water, usually within several seconds, or else the fulldrag reduction will not be achieved during transit through the wellbore.Surfactants have been used in the friction reducer emulsions to shortenthe flip time. Also, dilution of the friction reducer in a brinesolution has been used to collapse ionic polymer chains and reduce theviscosity of the concentrated friction reducer solution; however,storage stability has been an issue because any contact with freshwater, such as condensate dripping inside a storage tank, immediatelyforms fisheyes, which cannot be redispersed. It should be noted that thefisheyes form even thought the low viscosity brine-dilutedpolyacrylamide mixtures are clear solutions indicating no phaseseparation.

In the food industry, two-phase aqueous fluids are used to createpolymer solutions that mimic the properties of fat globules. In thebiomedical industry, such systems are exploited as separation media forproteins, enzymes, and other macromolecules that preferentiallypartition to one polymer phase in the mixture. When two or moredifferent water soluble polymers are dissolved together in an aqueousmedium, it is sometimes observed that the system phase separates intodistinct regions. For example, this happens when two polymers at highconcentration are chosen that are each water-soluble butthermodynamically incompatible with each other, e.g. polyethylene glycol(PEG) and dextran. Such two-phase systems are variously referred to inthe literature as water-in-water emulsions, biphasic systems, aqueoustwo phase systems (ATPS) or the like. Although they may be referred toas emulsions they do not necessarily contain either oil or surfactant.

Although numerous continuous mix systems are now in the oilfield, noneis completely satisfactory, and considerable need remains for systemswith improved hydration properties. This need is met at least in part bythe following invention.

SUMMARY OF THE INVENTION

Some embodiments of the present invention are based in part on thediscovery that water-in-water or other solvent-in-solvent emulsions canbe used to deliver polymers, especially rheology modifying polymers, todense brines and other well treatment fluids. Where the dispersed phasecomprises small polymer solution droplets or water-wet polymerparticles, the emulsions behave rheologically much like a slurry of hardparticles in the continuous phase. Thus, the apparent viscosity of theemulsion is influenced primarily by the rheology of the continuousphase, and not much at all by the viscosity of the dispersed phase. Theterm water-in-water emulsion as used herein is used to encompassmixtures comprising normally water-soluble polymers in the dispersedphase regardless of whether the dispersed phase is a liquid droplet oflow or high viscosity polymer solution, or a paste-like or water wetpolymer globule containing solid polymer particles, i.e. thewater-in-water emulsion is applicable to both liquid-liquid mixtures andliquid-solid slurries comprising water-soluble polymers.

In an embodiment, the present invention uses a partitioning agent thatseverely limits the solubility of a rheological agent, such as apolymer. As a result, the mixture forms a water-in-water emulsion wherea concentrated rheological agent is concentrated in the dispersed phase,as a viscous aqueous solution or as water-wet, hydrated, or partiallyhydrated particles, and the partitioning agent is concentrated in thecontinuous phase. One exemplary, non-limiting system comprises guar asthe viscosifying agent and polyethylene glycol (PEG) as the portioningagent. Guar is commonly used to viscosify treatment fluids at relativelylow concentrations, e.g. 0.1 weight percent, and at higherconcentrations in water the fluid can become too thick to pump or pour.The water-in-water emulsion of concentrated guar in embodiments of thepresent invention has a relatively low viscosity and is very easilypumped, but when diluted with water at the wellsite, the binodal pointis crossed and a continuous aqueous polymer phase forms to readilyviscosify the fluid.

The concentrated guar embodiment thus has a low viscosity convenient fortransport to the wellsite and/or preparation of the well treatmentfluid, but thickens rapidly when diluted in the treatment fluid.Moreover, and unexpectedly, partitioning agents such as the PEGembodiment can be used effectively in the water-in-water emulsions atconcentrations relative to the viscosifying polymer that, upon dilutionin the well treatment fluid, are sufficiently low to minimize anydeleterious effects on the treatment fluid in terms of, for example,rheology, stability, crosslinkability, and so on.

Another benefit of the water-in-water emulsion is that the mixture iseasily flowable or pumpable, even though a comparable mixture of thewater and polymer alone without any partitioning agent would be verythick or paste-like. This allows the water-in-water emulsion to be madeat high polymer content and at the same time the polymer particles arecontacted with the aqueous medium and at lest partially water swollen,while at the same time dispersed in the aqueous partitioning agentsolution. The swollen guar or other polymer in the water-in-wateremulsion thus has a head start on the hydration process and can thus behydrated in water or aqueous fluid more quickly relative to dry guar.

More importantly, the swollen guar in the water-in-water emulsion can befurther processed in beneficial ways to additionally enhance rapidhydration. For example, mechanical processing such as wet grinding ofthe water-in-water emulsion can be used to break the guar particles intosmaller pieces and thus achieve faster hydration, but without theproblems noted above in the prior art dry grinding. The swollen guarparticle is relatively larger and softer than the dry counterpart, whichfacilitates the grinding. In wet grinding, the heat generated can bedissipated in the liquid medium. Since the grinding is also cushioned bythe fluid, there is less reduction of the polymer molecular weight.Furthermore, the progressively smaller particles formed during the wetgrinding are already dispersed in water, and are not susceptible to formfish-eyes. Preheating the concentrated guar mixture can now be anefficient way to promote hydration since it is not necessary to heat theentire liquid phase of the well treatment fluid and the concentraterepresents only a small fraction of the total fluid.

In one embodiment, the invention provides a method of treating asubterranean formation penetrated by a well bore. The method can includethe steps of: (1) mixing a rheological polymer, a partitioning agent anda first liquid medium to form a heterogeneous mixture comprising adispersed rheological polymer-rich phase and a partitioning agent-richphase; (2) diluting the heterogeneous mixture with a second liquidmedium miscible with the first liquid medium to mutually dissolve thepolymer-rich phase and the partitioning-agent rich phase and form a welltreatment fluid comprising a continuous mixed polymer-agent phase; and(3) injecting the well treatment fluid into the well bore. Inembodiments, the rheological polymer can be a thickening polymereffective to increase the viscosity of the well treatment fluid; or afriction reducer effective to reduce friction pressure losses when thewell treatment fluid is pumped in the well bore at a high flow rate,e.g. 4 m/s.

In embodiments, the continuous mixed polymer-agent phase has an apparentviscosity at 1 l/s and 25° C. that is greater than the bulk apparentviscosity of the heterogeneous mixture; an apparent viscosity at 10 l/sand 25° C. that is greater than the bulk apparent viscosity of theheterogeneous mixture; or an apparent viscosity at 100 l/s and 25° C.that is greater than the bulk apparent viscosity of the heterogeneousmixture.

In an embodiment, the first and second liquid media can be aqueous andthe mixing step can further include at least partially hydrating thethickening polymer.

In an embodiment, the partitioning agent-rich phase can be continuousand the rheological-polymer-rich phase can be finely dispersed therein.

In embodiments, the first and second liquid media can be aqueous and thepartitioning agent can comprise a water soluble polymer.

In an embodiment, the mixing step comprises a weight ratio ofrheological polymer to partitioning agent from 1:4 to 4:1. Theheterogeneous mixture can comprise from 2 to 20 percent by weightrheological polymer based on the weight of the liquid media in theheterogeneous mixture. The continuous mixed polymer phase can comprisefrom 0.01 to 1 percent by weight rheological polymer based on the weightof the liquid media.

In an embodiment, the partitioning agent can comprise a polymer solublein the liquid media and having a solubility different with respect tothe rheological polymer. Concentrated solutions of the rheologicalpolymer and of the partitioning agent in the first liquid medium arepreferably immiscible. In embodiments, the rheological polymer can be apolysaccharide; the partitioning agent a polyalkylene oxide. In aparticular embodiment, the heterogeneous mixture can comprisepolyethylene glycol and one or more of guar, guar derivative, cellulose,cellulose derivative, heteropolysaccharide, heteropolysaccharidederivative, or polyacrylamide in an aqueous medium.

In an embodiment, the first liquid medium is aqueous and the secondliquid medium can be a high density brine. In another embodiment, thefirst and second liquid media can be aqueous, and the method can alsoinclude mechanically, thermally, or a combination of mechanicallythermally processing the heterogeneous mixture effective to increase arate of hydration of the polymer in the dilution step. The processingcan include, for example, wet grinding, high shear mixing,ultrasonification, heating, or the like, or any combination thereof.

In an embodiment, the liquid media can be aqueous and the partitioningagent can include nonionic surfactant. Additionally or alternatively,the method can further comprise the step of dispersing a gas phase inthe well treatment fluid to form an energized fluid or foam.

In another embodiment, the invention can provide a method of preparing awell treatment fluid, comprising the steps of: (1) mixing polyethyleneglycol and one or more polymers selected from the group consisting ofguar, modified guar, cellulose, modified cellulose,heteropolysaccharide, heteropolysaccharide derivative, orpolyacrylamide, with a first aqueous medium to hydrate the one or morepolymers and form a water-in-water emulsion; and (2) mixing thewater-in-water emulsion with a second aqueous medium to form a welltreatment fluid.

In embodiments, the water-in-water emulsion can comprise from 5 to 20percent of the one or more polymers, by weight of the water in theemulsion. The well treatment fluid can comprise from 0.01 to 1 weightpercent of the one or more polymers, by weight of the water in the welltreatment fluid.

Another embodiment of the invention provides a method of preparing apolymer concentrate for use in a fluid for treating a subterraneanformation penetrated by a well bore. The method for preparing theconcentrate can include the steps of: (a) admixing a rheologicalpolymer, a partitioning agent and a first aqueous medium to form aheterogeneous mixture comprising a dispersed polymer-rich phase and apartitioning agent-rich phase; and (b) mechanically, thermally, ormechanically and thermally processing the heterogeneous mixture toincrease a rate of hydration of the polymer upon dilution. Theprocessing step in various embodiments can include heating theheterogeneous mixture to a temperature above 60° C., wet grinding theheterogeneous mixture, high shear mixing of the heterogeneous mixture,e.g., at a shear rate above 1000 l/sec, ultrasonification of theheterogeneous mixture, or the like, including combinations thereof.

Another embodiment of the present invention provides the polymerconcentrate prepared by the method described above. In an embodiment,the heterogeneous mixture can include from 5 to 20 percent of therheological polymer, by weight of the water in the mixture, and a weightratio of the partitioning agent to the thickening polymer from 1:4 to4:1.

Another embodiment of the invention provides a method of preparing awell treatment fluid comprising mixing the polymer concentrate describedabove with a second aqueous medium to disperse the polymer in theresulting mixture. In an embodiment, the resulting mixture is completelydispersed within 90 seconds, preferably within 80, 70 or 60 seconds.

Another embodiment of the invention provides a method of treating asubterranean formation penetrated by a well bore comprising the stepsof: (a) mixing the polymer concentrate described above with a secondaqueous medium to disperse the polymer in the resulting mixture within90 seconds, and (b) injecting the resulting mixture into the well bore.

Another embodiment of the invention provides a concentrated viscosifyingadditive for preparing a well treatment fluid, comprising a pumpablewater-in-water emulsion of polyethylene glycol, one or more polymersselected from the group consisting of guar, modified guar, cellulose,modified cellulose, heteropolysaccharide, heteropolysaccharidederivative, or polyacrylamide, and one or more of an additament selectedfrom the group consisting of proppants, fibers, crosslinkers, breakers,breaker aids, friction reducers, surfactants, clay stabilizers, buffers,similar additives used in fluids in the oil and gas industry andcombinations thereof. In an embodiment, the water-in-water emulsioncomprises from 5 to 20 percent of the one or more polymers, by weight ofthe water in the emulsion, and a weight ratio of the polyethylene glycolto the one or more polymers is from 1:4 to 4:1.

A further embodiment of the invention provides apparatus for preparing awell treatment fluid. The apparatus can include a solids feeder forsupplying rheological polymer solids to a first mixing zone receiving ametered stream of a partitioning agent and a first aqueous stream toform a water-in-water emulsion stream. A dilution zone can be providedfor mixing the water-in-water emulsion stream with a second aqueousstream to mutually dissolve the rheological polymer- and thepartitioning agent and form a rheologically modified aqueous stream. Theapparatus can also include a line for supplying the rheologicallymodified aqueous stream to a stirred header tank, and additive pumps forsupplying one or more well treatment fluid additives to the header tank.

In an embodiment, the apparatus can also include a prehydrationprocessing unit for the water-in-water emulsion stream before thedilution zone. The prehydration processing unit can include, forexample, a wet grinder, a high shear mixer, a heater, an ultrasonicgenerator, or any combination thereof.

A further embodiment of the invention provides a method for supplying ahydrated polymer solution. The method can include the steps of: (a)supplying rheological polymer solids, a partitioning agent and a firstaqueous stream to a mixing zone to form a water-in-water emulsionstream; (b) optionally mechanically, thermally or mechanically andthermally processing the water-in-water emulsion stream to improvehydratability of the rheological polymer; and (c) supplying thewater-in-water emulsion stream with a second aqueous stream to adilution zone to form a rheologically modified aqueous stream.

In another embodiment, the invention provides the well treatment fluidprepared by any one of the embodiments of the methods described above,including any combination or permutation of the individual method steps.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates an approximated binodal curve for the aqueous systemsof guar and polyethylene glycol having a molecular weight of 8000 (PEG8000) in deionized (DI) water, wherein filled circles indicatesingle-phase mixtures and open circles indicate biphasic mixturescomprising low-viscosity guar concentrates, and wherein the diagonalline represents an embodiment of a dilution path for making a 0.5 wt %guar solution from a 1:1 guar:PEG 8000 concentrate.

FIG. 2 illustrates a phase diagram for guar mixed with PEG 8000 in DIwater including the binodal separating single-phase solutions fromtwo-phase solutions; the equivolumetric biphase line indicatingcompositions where equilibrium phase separation results in two phases ofequal volume, and wherein compositions above and below theequivolumetric biphase line form relatively larger and smallerconcentrated guar phases; and one embodiment according to the inventionof a limit line where the mixture can be diluted to 0.5 wt % guarwithout rheological changes due to the PEG 8000, corresponding to aweight ratio of guar:PEG 8000 of approximately 5:8.

FIG. 3 shows the rheology of 0.5 wt % guar solutions with and withoutaddition of PEG 8000, in terms of apparent viscosity versus shear rate,indicating that concentrations of PEG 8000 less than approximately 1 wt% do not measurably alter the rheology of 0.5 wt % guar solutionsaccording to one embodiment of the invention.

FIG. 4 shows the viscosities of the baseline Example 4 fluid preparedfrom dry guar and the inventive Example 5 fluid prepared from a guarconcentrate with PEG 8000, both in an otherwise identical boratecrosslinking formulation, at a shear rate of 100 s⁻¹ as the temperatureof the sample was increased from room temperature to 79.4° C. (175° F.).

FIG. 5 shows the viscosities at 100 s⁻¹ of the Example 4 and 5 fluidsfrom FIG. 4 were equivalent while the samples were held at the 79.4° C.(175° F.) temperature for two hours.

FIG. 6 shows the viscosities of two hydroxypropyl guars (HPG) of 0.6 and0.4 degree of substitution injected into dense CaCl₂ brine as dry HPGfor comparison and pre-hydrated HPG concentrates in water-in-wateremulsions according to the present invention, as described in Examples7-10, wherein each of the pre-hydrated HPG concentrate formulationsgenerated viscosity rapidly, and addition of dry HPG to the brine showedvery little viscosity development even after 30 minutes.

FIG. 7 shows the relationship between the rpm of a blender, charged withwater at relatively constant power to which guar is added all at once,and the viscosity of the guar solution, as a function of time, asdescribed in Example 11.

FIG. 8 shows the relationship between the percent hydration of the guarsolution in FIG. 7 as a function of time, from which the percenthydration can be correlated to blender rpm, as described in Example 11.

FIG. 9 compares the hydration curves for: dry guar (Example 11,comparative); a water-in-water emulsion of 10 wt % guar and 6 wt % PEG8000 prepared in a WARING blender (base WIWE, Example 12, inventive);the base WIWE processed with a SILVERSON high shear mixer for 10 minutes(Example 13, inventive); the base WIWE processed with a SILVERSON highshear mixer for 20 minutes (Example 14, inventive); and the base WIWEprocessed with an electric mortar for 10 minutes (Example 15,inventive), as described in Examples 11-15, according to embodiments ofthe invention.

FIG. 10 compares the hydration curves for a water-in-water emulsion of10 wt % guar and 6 wt % PEG 8000 prepared in a WARING blender (baseWIWE), and the base WIWE preheated to 65.6° C. (150° F.), as describedin Examples 12 and 16, according to embodiments of the invention.

FIG. 11 shows a schematic flow diagram for wellsite preparation of apolymer gel in a well treatment fluid, based on dry guar powder via awater-in-water emulsion process for prehydration, as described inExample 17, according to an embodiment of the invention.

DESCRIPTION OF THE INVENTION

At the outset, it should be noted that in the development of any suchactual embodiment, numerous implementation-specific decisions must bemade to achieve the developer's specific goals, such as compliance withsystem related and business related constraints, which will vary fromone implementation to another. Moreover, it will be appreciated thatsuch a development effort might be complex and time consuming but wouldnevertheless be a routine undertaking for those of ordinary skill in theart having the benefit of this disclosure. The description and examplesare presented solely for the purpose of illustrating the preferredembodiments of the invention and should not be construed as a limitationto the scope and applicability of the invention. While the compositionsof the present invention are described herein as comprising certainmaterials, it should be understood that the composition could optionallycomprise two or more chemically different materials. In addition, thecomposition can also comprise some components other than the onesalready cited.

In the summary of the invention and this description, each numericalvalue should be read once as modified by the term “about” (unlessalready expressly so modified), and then read again as not so modifiedunless otherwise indicated in context. Also, in the summary of theinvention and this detailed description, it should be understood that aconcentration range listed or described as being useful, suitable, orthe like, is intended that any and every concentration within the range,including the end points, is to be considered as having been stated. Forexample, “a range of from 1 to 10” is to be read as indicating each andevery possible number along the continuum between about 1 and about 10.Thus, even if specific data points within the range, or even no datapoints within the range, are explicitly identified or refer to only afew specific, it is to be understood that inventors appreciate andunderstand that any and all data points within the range are to beconsidered to have been specified, and that inventors have disclosed andenabled the entire range and all points within the range.

This invention relates to fluids used in treating a subterraneanformation, and in particular, the invention relates to the use ofwater-in-water emulsions to create concentrated polymer suspensionsuseful for creating wellbore fluids and in methods of treatingsubterranean formations. The invention is an improvement over theexisting art by providing a concentrated polymer suspension which can beconveniently prepared, easily stored and/or transported, and accuratelydelivered to the treatment fluid with minimum equipment and dissolutiontime. In an unexpected discovery, the use of water-in-water emulsionsmay also serve as a significant improvement for viscosifying densebrines for oilfield use.

Some embodiments of the invention incorporate the concept of aqueoustwo-phase systems as delivery systems for pre-hydrated wellsite polymerconcentrates. An advantage of the pre-hydrated concentrates inembodiments is the reduction or elimination of fish-eye formation whichotherwise can occur when it is attempted to disperse the dry polymer inwater. The presence of the partitioning agent in the preparation of thepolymer concentrate inhibits the formation of a coating gel over thepolymer particle aggregates, and even low shear mixing in manyembodiments will readily disaggregate and disperse the polymer particleswithin the solution of the partitioning agent. In one embodiment wherethe partitioning agent is more slowly dissolved in water, thepartitioning agent can be dissolved in water in advance of adding thepolymer particles. In any case, since the polymer is already dispersedand all the surfaces contacted with water when the aqueous concentrateis formed, the risk that fish-eyes will form when the polymer is used atthe wellsite is minimized. In one embodiment, the method of preparing awell treatment fluid or of treating a subterranean formation is free ofthe formation of fish-eyes.

Additionally, another important, unexpected discovery of the inventionis that these pre-hydrated polymer concentrates can rapidly viscosifyheavy brines. As used herein, a heavy brine, sometimes also called ahigh density brine or high brine, is an aqueous inorganic salt solutionhaving a specific gravity of greater than about 1.02 kg/L (8.5 lb/gal(ppg)), 1.08 kg/L (9 ppg) or 1.14 kg/L (9.5 ppg), especially above 1.2,1.32, 1.44 or 1.5 kg/L (10, 11, 12 or 12.5 ppg). This discovery suggeststhat the viscosification and other morphological characteristics of afluid with a polymer are strongly influenced by the process by which thepolymer is introduced, rather than simply the overall composition of thefinal fluid.

Another advantage of these water-in-water emulsion systems is that theyare very tolerant to any accidental water entering the concentrate, suchas, for example, condensation in a tote, whereas even small amounts ofwater present in non-aqueous polymer slurries or dry, free-flowingpowder or granulated polymer systems can render the material unusable.

Some embodiments of the invention use a low viscosity, concentratedpolymer solution for rapidly making polymer solutions at the wellsitewith minimal equipment and horsepower. Although not limited to anyspecific theory or mechanism of operation, it is believed that thewater-in-water emulsion allows the polymer to be dissolved or at leastpartially hydrated in a water phase without making an excessivelyviscous liquid carrier vehicle. This emulsion may be a phase-separatedfluid in which a polymer, which may be a high molecular weight,water-soluble polymer, and a partitioning agent, which may also be awater-soluble polymer and/or a low molecular weight, water-solublepolymer, are dissolved in water to create a low viscosity mixture.

It is believed that the mixture has a low viscosity due to thecontinuous phase having a very low concentration of the rheologicalpolymer, but the invention is not limited by this theory and isgenerally applicable to any polymer-concentrated, biphasic mixtures in amutual solvent or solvent system wherein dilution with additionalsolvent rapidly dissolves the rheological polymer in a monophasicsystem. In one embodiment the polymer concentrate can have a lowerviscosity than the corresponding polymer concentrate would have withoutthe partitioning agent, i.e. dilution with additional solvent canthicken the polymer solution. Such a pre-hydrated concentrated solutionor slurry, in the case of aqueous media, can be rapidly dispersed intoanother aqueous media, e.g. a water stream, to continuously makerheologically modified polymer solutions or gels for wellboretreatments. This can in an embodiment eliminate the disadvantages ofdissolving a dry polymer powder, or using a polymer slurried in oil, orusing an ionically collapsed polymer solution.

Some embodiments of the invention are based upon two-phasepolymer-polymer systems achievable with polymers of interest to theoilfield, e.g. viscosifiers, friction reducers, etc. Also, these twophase systems can be exploited to create low viscosity pre-hydrated (inthe case of aqueous solvent systems) or pre-solvated (in the case ofnon-aqueous solvents) concentrated mixtures to allow rapid polymermixing at a well site.

Some examples of polymers useful in the invention include polymers thatare either crosslinked or linear, or any combination thereof. Polymersinclude natural polymers, derivatives of natural polymers, syntheticpolymers, biopolymers, and the like, or any mixtures thereof. Anembodiment uses any viscosifying polymer used in the oil industry toform gels. Another embodiment uses any friction-reducing polymer used inthe oil industry to reduce friction pressure losses at high pumpingrates, e.g. in slickwater systems. Some non-limiting examples ofsuitable polymers include: polysaccharides, such as, for example, guargums, high-molecular weight polysaccharides composed of mannose andgalactose sugars, including guar derivatives such as hydropropyl guar(HPG), carboxymethyl guar (CMG), and carboxymethylhydroxypropyl guar(CMHPG), and other polysaccharides such as xanthan, diutan, andscleroglucan; cellulose derivatives such as hydroxyethyl cellulose(HEC), hydroxypropyl cellulose (HPC), carboxymethylhydroxyethylcellulose (CMHEC), and the like; synthetic polymers such as, but notlimited to, acrylic and methacrylic acid, ester and amide polymers andcopolymers, polyalkylene oxides such as polymers and copolymers ofethylene glycol, propylene glycol or oxide, and the like. The polymersare preferably water soluble. Also, associative polymers for whichviscosity properties are enhanced by suitable surfactants andhydrophobically modified polymers can be used, such as cases where acharged polymer in the presence of a surfactant having a charge that isopposite to that of the charged polymer, the surfactant being capable offorming an ion-pair association with the polymer resulting in ahydrophobically modified polymer having a plurality of hydrophobicgroups, as described published application US 2004209780.

As used herein, when a polymer is referred to as comprising a monomer orcomonomer, the monomer is present in the polymer in the polymerized formof the monomer or in the derivative form of the monomer. However, forease of reference the phrase comprising the (respective) monomer or thelike may be used as shorthand.

In some cases, the polymer or polymers are formed of a linear, nonionic,hydroxyalkyl galactomannan polymer or a substituted hydroxyalkylgalactomannan polymer. Examples of useful hydroxyalkyl galactomannanpolymers include, but are not limited to, hydroxy-C₁-C₄-alkylgalactomannans, such as hydroxy-C₁-C₄-alkyl guars. Preferred examples ofsuch hydroxyalkyl guars include hydroxyethyl guar (HE guar),hydroxypropyl guar (HP guar), and hydroxybutyl guar (HB guar), and mixedC₂-C₄, C₂/C₃, C₃/C₄, or C₂/C₄ hydroxyalkyl guars. Hydroxymethyl groupscan also be present in any of these.

As used herein, substituted hydroxyalkyl galactomannan polymers areobtainable as substituted derivatives of the hydroxy-C₁-C₄-alkylgalactomannans, which include: 1) hydrophobically-modified hydroxyalkylgalactomannans, e.g., C₁-C₂₄-alkyl-substituted hydroxyalkylgalactomannans, e.g., wherein the amount of alkyl substituent groups ispreferably about 2 percent by weight or less by weight of thehydroxyalkyl galactomannan; and 2) poly(oxyalkylene)-graftedgalactomannans (see, e.g., A. Bahamdan & W. H. Daly, in Proc. 8PthPPolymers for Adv. Technol. Int'l Symp. (Budapest, Hungary, September2005) (PEG- and/or PPG-grafting is illustrated, although applied thereinto carboxymethyl guar, rather than directly to a galactomannan))Poly(oxyalkylene)-grafts thereof can comprise two or more than twooxyalkylene residues; and the oxyalkylene residues can be C₁-C₄oxyalkylenes. Mixed-substitution polymers comprising alkyl substituentgroups and poly(oxyalkylene) substituent groups on the hydroxyalkylgalactomannan are also useful herein. In various embodiments ofsubstituted hydroxyalkyl galactomannans, the ratio of alkyl and/orpoly(oxyalkylene) substituent groups to mannosyl backbone residues canbe about 1:25 or less, i.e. with at least one substituent perhydroxyalkyl galactomannan molecule; the ratio can be: at least or about1:2000, 1:500, 1:100, or 1:50; or up to or about 1:50, 1:40, 1:35, or1:30. Combinations of galactomannan polymers according to the presentdisclosure can also be used.

As used herein, galactomannans in one embodiment comprise a polymannosebackbone attached to galactose branches that are present at an averageratio of from 1:1 to 1:5 galactose branches:mannose residues. Preferredgalactomannans comprise a 1→4-linked β-D-mannopyranose backbone that is1→6-linked to α-D-galactopyranose branches. Galactose branches cancomprise from 1 to about 5 galactosyl residues; in various embodiments,the average branch length can be from 1 to 2, or from 1 to about 1.5residues. Preferred branches are monogalactosyl branches. In variousembodiments, the ratio of galactose branches to backbone mannoseresidues can be, approximately, from 1:1 to 1:3, from 1:1.5 to 1:2.5, orfrom 1:1.5 to 1:2, on average. In various embodiments, the galactomannancan have a linear polymannose backbone. The galactomannan can be naturalor synthetic. Natural galactomannans useful herein include plant andmicrobial (e.g., fungal) galactomannans, among which plantgalactomannans are preferred. In various embodiments, legume seedgalactomannans can be used, examples of which include, but are notlimited to: tara gum (e.g., from Cesalpinia spinosa seeds) and guar gum(e.g., from Cyamopsis tetragonoloba seeds). In addition, althoughembodiments of the present invention may be described or exemplifiedwith reference to guar, such as by reference to hydroxy-C₁-C₄-alkylguars, such descriptions apply equally to other galactomannans, as well.

The selection of the partitioning agent depends on the polymer that isto be concentrated in the heterogeneous mixture, as well as the solventsystem, e.g. aqueous, non-aqueous, oil, etc. In one embodiment ingeneral, the partitioning agent is soluble in the solvent medium, buthas dissimilar thermodynamic properties such that a solution thereof isimmiscible with a solution of the polymer at concentrations above abinodal curve for the system, or such that a solid phase of the polymerwill not dissolve in a solution of the portioning agent at theconcentration in the system. For example, where the polymer is a highmolecular weight hydrophilic polymer, the partitioning agent can be alow molecular weight hydrophobic polymer. For guar and polymersthermodynamically similar to guar, the partitioning agent in anembodiment is a polyoxyalkylene, wherein the oxyalkylene units comprisefrom one to four carbon atoms, such as, for example a polymer ofethylene glycol, propylene glycol or oxide, or a combination thereof,having a weight average molecular weight from 1000 to 25,000. As usedherein, “polyoxyalkylene” and refers to homopolymers and copolymerscomprising at least one block, segment, branch or region composed ofoxyalkylene repeat units, e.g. polyethylene glycol. Polyethylene glycol(PEG) having a molecular weight between 2000 and 10,000 is widelycommercially available. Other embodiments comprise methoxy-PEG (mPEG);poloxamers available as PEG-polypropylene oxide (PPO) triblockcopolymers under the trade designation PLURONICS; alkylated andhydroxyalkylated PEG available under the trade designation BRIJ, e.g.BRIJ 38; and the like.

Other examples of partitioning agents can include polyvinyl pyrrolidone,vinyl pyrrolidine-vinyl acetate copolymers, and hydroxyalkylated orcarboxyalkylated cellulose, especially low molecular weighthydroxyalkylated cellulose such as hydroxypropyl cellulose having amolecular weight of about 10,000.

Another embodiment of partitioning agents comprises the class of watersoluble chemicals known as non-ionic surfactants. These surfactantscomprise hydrophilic and hydrophobic groups, that is, they areamphiphilic, but are electrophilically neutral, i.e. uncharged. Nonionicsurfactants can be selected from the group consisting of alkylpolyethylene oxides (such as BRIJ surfactants, for example),polyethylene oxide-polypropylene oxide copolymers (such as poloxamers orpoloxamines, for example), alkyl-, hydroxyalkyl- and alkoxyalkylpolyglucosides (such as octyl or decyl glucosides or maltosides), fattyalcohols, fatty acid amides, and the like.

In an embodiment, the heterogeneous polymer concentrate can have anysuitable weight ratio of rheological polymer to partitioning agent thatprovides a heterogeneous mixture, i.e. a binary liquid mixture or asolid-liquid slurry. If the ratio of polymer:partitioning agent is toohigh, the mixture becomes too thick to pour or pump, or may even form apaste; if too low, the partitioning agent upon dilution may have anadverse impact on the polymer solution or well treatment fluid. Apolymer:partitioning agent ratio from 1:4 to 4:1 may be suitablyemployed, or higher or lower ratios may be used where the abovementioneddisadvantages are avoided. In one embodiment, the polymer:partitioningagent ratio is from 1:2 to 2.5:1, preferably from 3:5 to 5:3.

The heterogeneous mixture can comprise anywhere upwards from 1 percentby weight rheological polymer, based on the weight of the liquid in theheterogeneous mixture, up to any maximum upper limit where the mixtureis no longer fluid, e.g. pumpable or pourable using conventionaloilfield pumping equipment. Lower concentrations of rheological polymermay provide little or no benefit because the dilution rate to obtain thetreatment fluid is too low to be practical. For example, to prepare anaqueous treatment fluid with a polymer concentration of 0.5 weightpercent, a 1 wt % concentrate would be mixed with water (or other liquidmedia) at 1:1 whereas a 20 wt % concentrate could be mixed at 40:1. Inembodiments, the heterogeneous aqueous concentrate comprises a range offrom a lower limit of 1, 2, 3 or 5 up to an upper limit of 10, 15 or 20percent by weight of the polymer, by weight of the water or other liquidin the mixture.

The water-in-water emulsion may further include other additives such asdispersing aids, surfactants, pH adjusting compounds, buffers,antioxidants, colorants, biocides, which do not materially change themiscibility or solubility of the heterogeneous phases, or interfere withthe desirable characteristics of the well treatment fluid. The polymerconcentrate can include any additive that is to be introduced into thewell treatment fluid separately, provided that it is essentially inertin the concentrate. In one embodiment, at least one other well treatmentfluid additive is present in the polymer concentrate, such as, forexample, proppants, fibers, crosslinkers, breakers, breaker aids,friction reducers, surfactants, clay stabilizers, buffers, and the like.The other additive can also be concentrated in the polymer concentrateso that the additive does not need to be added to the well treatmentfluid separately, or can be added in a lesser amount. This can beadvantageous where the other additive is usually added proportionallywith respect to the polymer. Also, the activity of an additive(s) can bedelayed, in one embodiment, and the delay can at least in part befacilitated where the additive is preferentially concentrated in thepartitioning agent-rich phase or otherwise reactively separated from thepolymer.

The water-in-water emulsion can also include or be mixed in ahydrophobic liquid, e.g. an oil-in-water or an invert (water-in-oil)emulsion wherein the aqueous phase in the oil emulsion comprises thewater-in-water emulsion. In one embodiment, the oil-in-(water-in-wateremulsion) emulsion can comprise a relatively high volume of oil in adiscontinuous phase, for example, 90 volume percent or greater oil.

When incorporated in the well treatment or other fluid, for example upondilution of the water-in-water polymer concentrates in a second aqueousmedium, the viscosifying polymers may be present at any suitableconcentration. In various embodiments hereof, the rheological polymercan be present in an amount of from about 0.01 g/L of fluid (0.1lb/1000gal of fluid (ppt)) to less than about 7.2 g/L (60 ppt), or from about0.018 to about 4.8 g/L (about 1.5 to about 40 ppt), from about 0.018 toabout 4.2 g/L (about 1.5 to about 35 ppt), or from 0.018 to about 3 g/L(1.5 to about 25 ppt), or even from about 0.24 to about 1.2 g/L (about 2to about 10 ppt). Friction reducing polymers are generally diluted foruse in the treatment fluid to a concentration from 0.01 to 0.4 percentby weight of the liquid phase, especially from 0.025 to 0.2 percent byweight of the liquid phase. In other embodiments, the polymer is dilutedfrom the concentrate into the treatment or other fluid at a rate withina range of from any lower limit selected from 0.0001, 0.001, 0.01,0.025, 0.05, 0.1, or 0.2 percent by weight of the liquid phase, up toany higher upper limit selected from 1.0, 0.5, 0.4, 0.25, 0.2, 0.15 or0.1 percent by weight of the liquid phase.

Some fluid compositions useful in some embodiments of the invention mayalso include a gas component, produced from any suitable gas that formsan energized fluid or foam when introduced into an aqueous medium. See,for example, U.S. Pat. No. 3,937,283 (Blauer et al.) incorporated hereinby reference. Preferably, the gas component comprises a gas selectedfrom the group consisting of nitrogen, air, argon, carbon dioxide, andany mixtures thereof. More preferably the gas component comprisesnitrogen or carbon dioxide, in any quality readily available. The gascomponent may assist in the fracturing and acidizing operation, as wellas the well clean-up process.

The fluid in one embodiment may contain from about 10% to about 90%volume gas component based upon total fluid volume percent, preferablyfrom about 20% to about 80% volume gas component based upon total fluidvolume percent, and more preferably from about 30% to about 70% volumegas component based upon total fluid volume percent. In one embodiment,the fluid is a high-quality foam comprising 90 volume percent or greatergas phase. In one embodiment, the partitioning agent used in the polymerdelivery system can be selected to enhance the characteristics of theenergized fluid or foam, such as gas phase stability or viscosity, forexample, where the partitioning agent is a surfactant such as a nonionicsurfactant, especially the alkoxylated (e.g., ethoxylated) surfactantsavailable under the BRIJ designation.

In some embodiments, the fluids used may further include a crosslinker.Adding crosslinkers to the fluid may further augment the viscosity ofthe fluid. Crosslinking consists of the attachment of two polymericchains through the chemical association of such chains to a commonelement or chemical group. Suitable crosslinkers may comprise a chemicalcompound containing a polyvalent ion such as, but not necessarilylimited to, boron or a metal such as chromium, iron, aluminum, titanium,antimony and zirconium, or mixtures of polyvalent ions. The crosslinkercan be delayed, in one embodiment, and the delay can at least in part befacilitated where the crosslinker or activator is concentrated orotherwise reactively separated in the partitioning agent-rich phase.

The fluids of some embodiments of the invention may include anelectrolyte which may be an organic acid, organic acid salt, organicsalt, or inorganic salt. Mixtures of the above members are specificallycontemplated as falling within the scope of the invention. This memberwill typically be present in a minor amount (e.g. less than about 30% byweight of the liquid phase). The organic acid is typically a sulfonicacid or a carboxylic acid, and the anionic counter-ion of the organicacid salts is typically a sulfonate or a carboxylate. Representative ofsuch organic molecules include various aromatic sulfonates andcarboxylates such as p-toluene sulfonate, naphthalene sulfonate,chlorobenzoic acid, salicylic acid, phthalic acid and the like, wheresuch counter-ions are water-soluble. Most preferred organic acids areformic acid, citric acid, 5-hydroxy-1-napthoic acid,6-hydroxy-1-napthoic acid, 7-hydroxy-1-napthoic acid,1-hydroxy-2-naphthoic acid, 3-hydroxy-2-naphthoic acid,5-hydroxy-2-naphthoic acid, 7-hydroxy-2-napthoic acid,1,3-dihydroxy-2-naphthoic acid, and 3,4-dichlorobenzoic acid.

The inorganic salts that are particularly suitable include, but are notlimited to, water-soluble potassium, sodium, and ammonium salts, such aspotassium chloride and ammonium chloride. Additionally, magnesiumchloride, calcium chloride, calcium bromide, zinc halide, sodiumcarbonate, and sodium bicarbonate salts may also be used. Any mixturesof the inorganic salts may be used as well. The inorganic salts may aidin the development of increased viscosity that is characteristic ofpreferred fluids. Further, the inorganic salt may assist in maintainingthe stability of a geologic formation to which the fluid is exposed.Formation stability and in particular clay stability (by inhibitinghydration of the clay) is achieved at a concentration level of a fewpercent by weight and as such the density of fluid is not significantlyaltered by the presence of the inorganic salt unless fluid densitybecomes an important consideration, at which point, heavier inorganicsalts may be used. In some embodiments of the invention, the electrolyteis an organic salt such as tetramethyl ammonium chloride, or inorganicsalt such as potassium chloride. The electrolyte is preferably used inan amount of from about 0.01 wt % to about 12.0 wt % of the total liquidphase weight, and more preferably from about 0.1 wt % to about 8.0 wt %of the total liquid phase weight.

Fluids used in some embodiments of the invention may also comprise anorganoamino compound. Examples of suitable organoamino compoundsinclude, but are not necessarily limited to, tetraethylenepentamine,triethylenetetramine, pentaethylenehexamine, triethanolamine, and thelike, or any mixtures thereof. When organoamino compounds are used influids of the invention, they are incorporated at an amount from about0.01 wt % to about 2.0 wt % based on total liquid phase weight.Preferably, when used, the organoamino compound is incorporated at anamount from about 0.05 wt % to about 1.0 wt % based on total liquidphase weight. A particularly useful organoamino compound istetraethylenepentamine, particularly when used with diutan viscosifyingagent at temperatures of approximately 300° F.

Breakers may optionally be used in some embodiments of the invention.The purpose of this component is to “break” or diminish the viscosity ofthe fluid so that this fluid is even more easily recovered from theformation during cleanup. With regard to breaking down viscosity,oxidizers, enzymes, or acids may be used. Breakers reduce the polymer'smolecular weight by the action of an acid, an oxidizer, an enzyme, orsome combination of these on the polymer itself In the case ofborate-crosslinked gels, increasing the pH and therefore increasing theeffective concentration of the active crosslinker (the borate anion),will allow the polymer to be crosslinked. Lowering the pH can just aseasily eliminate the borate/polymer bonds. At pH values at or above 8,the borate ion exists and is available to crosslink and cause gelling.At lower pH, the borate is tied up by hydrogen and is not available forcrosslinking, thus gelation caused by borate ion is reversible.Preferred breakers include 0.1 to 20 pounds per thousands gallons ofconventional oxidizers such as ammonium persulfates, live orencapsulated, or potassium periodate, calcium peroxide, chlorites, andthe like. In oil producing formations the film may be at least partiallybroken when contacted with formation fluids (oil), which may helpde-stabilize the film. The breaker can be delayed, in one embodiment,and the delay can at least in part be facilitated where the breaker orbreaker activator is concentrated or otherwise reactively separated inthe partitioning agent-rich phase.

A fiber component may be included in the fluids used in the invention toachieve a variety of properties including improving particle suspension,and particle transport capabilities, and gas phase stability. Fibersused may be hydrophilic or hydrophobic in nature, but hydrophilic fibersare preferred. Fibers can be any fibrous material, such as, but notnecessarily limited to, natural organic fibers, comminuted plantmaterials, synthetic polymer fibers (by non-limiting example polyester,polyaramide, polyamide, novoloid or a novoloid-type polymer),fibrillated synthetic organic fibers, ceramic fibers, inorganic fibers,metal fibers, metal filaments, carbon fibers, glass fibers, ceramicfibers, natural polymer fibers, and any mixtures thereof. Particularlyuseful fibers are polyester fibers coated to be highly hydrophilic, suchas, but not limited to, DACRON® polyethylene terephthalate (PET) Fibersavailable from Invista Corp. Wichita, Kans., USA, 67220. Other examplesof useful fibers include, but are not limited to, polylactic acidpolyester fibers, polyglycolic acid polyester fibers, polyvinyl alcoholfibers, and the like. When used in fluids of the invention, the fibercomponent may be included at concentrations from about 1 to about 15grams per liter of the liquid phase of the fluid, preferably theconcentration of fibers are from about 2 to about 12 grams per liter ofliquid, and more preferably from about 2 to about 10 grams per liter ofliquid.

Embodiments of the invention may use other additives and chemicals thatare known to be commonly used in oilfield applications by those skilledin the art. These include, but are not necessarily limited to, materialsin addition to those mentioned hereinabove, such as breaker aids, oxygenscavengers, alcohols, scale inhibitors, corrosion inhibitors, fluid-lossadditives, bactericides, iron control agents, organic solvents, and thelike. Also, they may include a co-surfactant to optimize viscosity or tominimize the formation of stabilized emulsions that contain componentsof crude oil, or as described hereinabove, a polysaccharide orchemically modified polysaccharide, natural polymers and derivatives ofnatural polymers, such as cellulose, derivatized cellulose, guar gum,derivatized guar gum, or biopolymers such as xanthan, diutan, andscleroglucan, synthetic polymers such as polyacrylamides andpolyacrylamide copolymers, oxidizers such as persulfates, peroxides,bromates, chlorates, chlorites, periodates, and the like. Some examplesof organic solvents include ethylene glycol monobutyl ether, isopropylalcohol, methanol, glycerol, ethylene glycol, mineral oil, mineral oilwithout substantial aromatic content, and the like.

Embodiments of the invention may also include placing proppant particlesthat are substantially insoluble in the fluids. Proppant particlescarried by the treatment fluid remain in the fracture created, thuspropping open the fracture when the fracturing pressure is released andthe well is put into production. Suitable proppant materials include,but are not limited to, sand, walnut shells, sintered bauxite, glassbeads, ceramic materials, naturally occurring materials, or similarmaterials. Mixtures of proppants can be used as well. If sand is used,it will typically be from about 20 to about 100 U.S. Standard Mesh insize. Naturally occurring materials may be underived and/or unprocessednaturally occurring materials, as well as materials based on naturallyoccurring materials that have been processed and/or derived. Suitableexamples of naturally occurring particulate materials for use asproppants include, but are not necessarily limited to: ground or crushedshells of nuts such as walnut, coconut, pecan, almond, ivory nut, brazilnut, etc.; ground or crushed seed shells (including fruit pits) of seedsof fruits such as plum, olive, peach, cherry, apricot, etc.; ground orcrushed seed shells of other plants such as maize (e.g., corn cobs orcorn kernels), etc.; processed wood materials such as those derived fromwoods such as oak, hickory, walnut, poplar, mahogany, etc. includingsuch woods that have been processed by grinding, chipping, or other formof particalization, processing, etc. Further information on nuts andcomposition thereof may be found in Encyclopedia of Chemical Technology,Edited by Raymond E. Kirk and Donald F. Othmer, Third Edition, JohnWiley & Sons, Volume 16, pages 248-273 (entitled “Nuts”), Copyright1981, which is incorporated herein by reference.

The concentration of proppant in the fluid can be any concentrationknown in the art, and will preferably be in the range of from about 0.05to about 3 kilograms of proppant added per liter of liquid phase. Also,any of the proppant particles can further be coated with a resin topotentially improve the strength, clustering ability, and flow backproperties of the proppant.

Conventional propped hydraulic fracturing techniques, with appropriateadjustments if necessary, as will be apparent to those skilled in theart, are used in some methods of the invention. One preferred fracturestimulation treatment according to the present invention typicallybegins with a conventional pad stage to generate the fracture, followedby a sequence of stages in which a viscous carrier fluid transportsproppant into the fracture as the fracture is propagated. Typically, inthis sequence of stages the amount of propping agent is increased,normally stepwise. The pad and carrier fluid can be a fluid of adequateviscosity. The pad and carrier fluids may contain various additives.Non-limiting examples are fluid loss additives, crosslinking agents,clay control agents, breakers, iron control agents, and the like,provided that the additives do not affect the stability or action of thefluid.

The procedural techniques for pumping fracture stimulation fluids down awellbore to fracture a subterranean formation are well known. The personthat designs such fracturing treatments is the person of ordinary skillto whom this disclosure is directed. That person has available manyuseful tools to help design and implement the fracturing treatments, oneof which is a computer program commonly referred to as a fracturesimulation model (also known as fracture models, fracture simulators,and fracture placement models). Most if not all commercial servicecompanies that provide fracturing services to the oilfield have one ormore fracture simulation models that their treatment designers use. Onecommercial fracture simulation model that is widely used by severalservice companies is known as FracCADE™. This commercial computerprogram is a fracture design, prediction, and treatment-monitoringprogram designed by Schlumberger, Ltd. All of the various fracturesimulation models use information available to the treatment designerconcerning the formation to be treated and the various treatment fluids(and additives) in the calculations, and the program output is a pumpingschedule that is used to pump the fracture stimulation fluids into thewellbore. The text “Reservoir Stimulation,” Third Edition, Edited byMichael J. Economides and Kenneth G. Nolte, Published by John Wiley &Sons, (2000), is an excellent reference book for fracturing and otherwell treatments; it discusses fracture simulation models in Chapter 5(page 5-28) and the Appendix for Chapter 5 (page A-15)), which areincorporated herein by reference.

In the fracturing treatment, fluids of the invention may be used in thepad treatment, the proppant stage, or both. The components of the liquidphase are preferably mixed on the surface. Alternatively, a the fluidmay be prepared on the surface and pumped down tubing while the gascomponent could be pumped down the annular to mix down hole, or viceversa.

Yet another embodiment of the invention includes cleanup method. Theterm “cleanup” or “fracture cleanup” refers to the process of removingthe fracture fluid (without the proppant) from the fracture and wellboreafter the fracturing process has been completed. Techniques forpromoting fracture cleanup traditionally involve reducing the viscosityof the fracture fluid as much as practical so that it will more readilyflow back toward the wellbore. While breakers are typically used incleanup, the fluids of the invention may be effective for use in cleanupoperations, with or without a breaker.

In another embodiment, the invention relates to gravel packing awellbore. A gravel packing fluid, it preferably comprises gravel or sandand other optional additives such as filter cake clean up reagents suchas chelating agents referred to above or acids (e.g. hydrochloric,hydrofluoric, formic, acetic, citric acid) corrosion inhibitors, scaleinhibitors, biocides, leak-off control agents, among others. For thisapplication, suitable gravel or sand is typically having a mesh sizebetween 8 and 70 U.S. Standard Sieve Series mesh.

In some embodiments of the invention, water-in-water emulsions are usedto provide friction reducers, such as acrylamide polymers and copolymershaving pendant cationic and/or anionic groups. By using the frictionreducer as the rheological polymer in the water-in-water emulsion, thefriction reducer can be provided as a stable concentrate that canrapidly flip when diluted with water to allow the polymer to becomecompletely solubilized in an aqueous treatment fluid, especially aslickwater fluid where the friction reducer is added on the fly. Also,in many environments, it would be a particular advantage to be able toviscosify produced waters, river waters, and other “difficult waters”that contain high concentrations of salts or boron, and some embodimentsof the invention include forming and treating a subterranean formationwith a fluid formed of water-in-water emulsions of the invention andsuch produced waters, river waters, and other difficult waters.

The following examples are presented to illustrate the preparation andproperties of energized aqueous fluids comprising heteropolysaccharidesand a surfactant, and should not be construed to limit the scope of theinvention, unless otherwise expressly indicated in the appended claims.All percentages, concentrations, ratios, parts, etc. are by weightunless otherwise noted or apparent from the context of their use.

EXAMPLES Example 1

A low viscosity aqueous suspension of guar with PEG 8000. A series ofpolymer solutions was created by dissolving 0-4 weight percent dry guarand 0-4 weight percent dry polyethylene glycol (PEG 8000) in deionized(DI) water. In each case, 200 ml of DI water were used, and the polymerswere measured as dry powders with percentages expressed on a total fluidweight basis. For each sample, the dry polymers were mixed together andthen added together into the DI water while stirring vigorously in aWARING blender. Each sample was stirred rapidly in the blender for aminimum of one hour. After this stirring process, each sample wasvisually inspected for evidence of phase separation. Samples weremonitored for a period of at least 24 hours to check for phaseseparation. The results were plotted in FIG. 1 using filled circles 10to indicate no phase separation and open circles 12 to indicate theoccurrence of phase separation.

The low-viscosity concentrates 12 fell within the two-phase regiondemarcated by the binodal curve 14 approximated in FIG. 1. It should bepointed out that although these concentrations had considerable guar,they were not suspensions of dry guar in diesel or some other oil, sincethe guar was hydrated in water. When the guar concentrate was dilutedwith additional DI water to approximately 0.5 weight percent, it formedlinear gel very rapidly without any fish-eye formation and withoutrequiring an extensive hydration process, unlike a dry polymer additionor a dry polymer-oil slurry addition.

As an example, one series of fluids was made with 1 weight percent guarbased upon total fluid weight, but with different amounts of PEG 8000,i.e. 0, 1, 1.5, 2, 3 and 4 weight percent based on total fluid weight.At the higher concentrations of PEG 8000 in FIG. 1, the samples wereseen to phase separate over a period of a few hours, but no phaseseparation occurred for the lower PEG 8000 concentrations. When stirred,the phase-separated solutions 12 readily dispersed to provide lowviscosity suspensions of guar polymer.

The diagonal line 16 thus represents an embodiment of a dilution pathfor making a 0.5 wt % guar gel from a 1:1 guar:PEG 8000 concentrate. Itshould be noted that the phase diagram in FIG. 1 does not suggest anupper limit as to the amount of polymer that can be concentrated in sucha way. Pourable water-in-water emulsions with 20 wt % guarconcentrations have been successfully formulated.

Example 2

Wellsite guar delivery system using low viscosity aqueous suspension.FIG. 2 provides a phase diagram for a high molecular weight guarroutinely used for wellbore treatment fluids. As in the phase diagram ofFIG. 1, the guar in this example was again phase separated with PEG8000. Line 20 on the phase diagram indicates the binodal for phaseseparation, with compositions to the upper-right of line 20 being lowviscosity two-phase solutions of the two polymers in water. Line 22 inthe two-phase region indicates the line of compositions having 50/50phase volume upon phase separation; line 24 a 60/40 phase volume ofguar:PEG 8000; and line 26 a 40/60 phase volume of guar:PEG 8000. Thepercentages beside some of the points are the volume percent of theseparated guar phase at equilibrium. Below-right with respect to theline 24 (60/40 guar:PEG 8000) represents readily pourable compositions;compositions above 60 to about 80 volume percent guar phase areborderline pumpable, generally resembling applesauce in texture; andcompositions above 80 volume percent guar phase generally have apaste-like consistency.

Limit line 28 represents an embodiment of the maximum PEG 8000concentration where the mixture can be safely diluted to 0.5 wt % guarwithout rheological changes due to the PEG 8000, corresponding to aweight ratio of guar:PEG 8000 of approximately 5:8.

Although a wide range of low viscosity polymer concentrates have beenidentified in the phase diagram of FIG. 2, the composition 30 at 10%guar, 6% PEG 8000 was selected as an example point for demonstrating howan aqueous polymer concentrate can be used in a delivery system formaking an exemplary treatment fluid. Composition 30 can be preparedoffsite, delivered to the wellsite, and diluted approximately 20:1 withwater to 0.5 weight percent guar and 0.3 weight percent PEG 8000. Thisexample shows that, in some embodiments of the invention, use oftwo-phase polymer solutions for wellsite delivery has the unexpectedresult that the phase diagram yields a critical region in the phasespace where linear guar solutions diluted from the concentrate areessentially indistinguishable from the same fluids made from only guarand water, in terms of rheology, stability or crosslinking properties.That is, the presence of a certain amount of PEG 8000 or otherpartitioning agent in the concentrate may not, upon dilution in thetreatment fluid, measurably alter the rheology, stability orcrosslinking properties of the guar in solution. The area 32 from zeroto 1% for both guar and PEG concentration in FIG. 2 indicates such aregion.

Example 3

Effect of diluted PEG 8000 on viscosity of linear gels. FIG. 3 shows therheology of 0.5 wt % guar solutions with and without addition of PEG8000, in terms of apparent viscosity versus shear rate. Concentrationsof PEG 8000 less than approximately 1 wt % do not measurably alter therheology of 0.5 wt % guar solutions. Specifically, the data shown inFIG. 3 illustrate that addition of PEG 8000 to a 0.5% guar solution (40lbs/1000 gallons) has negligible impact on the guar solution rheologyfor PEG 8000 concentrations up to at least 1 wt %. This is a critical,unexpected result, that a phase-separated, low viscosity concentrate canbe used to deliver guar as a treatment fluid, without sacrificing theperformance of the guar fluid thus made when the dilution is performedto create a final fluid composition within the area 32 from zero to 1%for both guar and PEG concentration in FIG. 2.

Examples 4 and 5

Effect of guar concentrates in PEG 8000 on crosslinked treatment fluidproperties. To investigate the usefulness of the guar concentrate formaking treatment fluids and any adverse impact of the PEG 8000,crosslinked 0.3 wt % guar solutions were made two different ways. First,a baseline fluid (Example 4) was made from dry guar powder added to thefluid for comparison with the equivalent fluid made from an aqueoustwo-polymer concentrate. The baseline fluid was made and crosslinked ina standard treatment fluid formulation based upon de-ionized water (100mL), 50% solution of tetramethyl ammonium chloride (0.2 mL), solution of60% of sodium gluconate and 32% of boric acid (0.12 mL), and 30%solution of sodium hydroxide (0.08 ml). Second, for Example 5, the samefluid was made from an aqueous guar concentrate containing 10 wt % guarand 6 wt % PEG 8000, previously identified as composition 30 on thephase diagram of FIG. 2. By dilution, the second fluid contained 0.18 wt% PEG 8000, as well as 0.3 wt % guar, thereby placing it well withinarea 32 for dilution as identified in FIG. 2. As with the baselinefluid, this second fluid was crosslinked with a combination sodiumgluconate, boric acid, and sodium hydroxide at a pH of approximately 10.

The viscosities of the baseline Example 4 fluid and the inventiveExample 5 fluid at a shear rate of 100 s⁻¹ were continuously monitoredas the temperature of the sample was increased from room temperature to79.4° C. (175° F.). The results plotted in FIG. 4 indicate that thepresence of the 0.18 wt % PEG 8000 in Example 5 had no measurable impacton the performance of the crosslinked guar made from the concentraterelative to the Example 4 baseline. Upon heating to 79.4° C. (175° F.),the samples were held at this temperature and the viscosity at 100 s⁻¹continuously monitored. As shown in FIG. 5, the performance of thefluids of Example 4 (baseline) and Example 5 (with PEG 8000) weresubstantially equivalent.

Example 6

A low-viscosity aqueous suspension of diutan. A low-viscosityconcentrated solution of diutan was formulated by combining diutan at 10weight percent in DI water with 20 weight percent water soluble polymercomprising the sodium salt of polynaphthalene sulfonate-formaldehydecondensate, mol wt 8000, and 3 weight percent of a PEG-PPO-PEG triblocknonionic surfactant. This multi-polymer solution was mixed by firstdissolving the water soluble polymer and surfactant in water for severalminutes and then slowly adding the diutan polymer. Once all the diutanwas added, the solution was mixed vigorously in a WARING blender for 1hour to assure complete mixing and dissolution of the polymers. Thefinal solution had a very low viscosity, was easily pourable, and slowlyphase separated into diutan-rich and diutan-lean phases after sittingfor approximately twelve hours. The phase-separated solution was easilyresuspended, however, with gentle stirring. The 10 weight percent diutansolution was diluted into fresh water to rapidly make a viscous 1 weightpercent diutan gel.

Examples 7-10

Rapidly viscosifying a heavy brine fluid with a pre-hydrated suspensionof hydroxypropyl guar (HPG). In Examples 7 and 8, baseline runs usingdry guar, 0.5 wt % HPG was measured as a dry powder and dispersed intoCaCl₂ brine having a density of 1.318 g/mL (11.0 lb/gal or ppg) in astirred WARING blender. In Example 7, the HPG had 0.6 molarsubstitution, JAGUAR HP-60; and in Example 8, HPG with 0.4 molarsubstitution, ECOPOL 400DS, was used. Mixing with HPG started at time 0on the plot of FIG. 6 and continued for 2.5 minutes. Viscosity wasmeasured with a Fann 35 viscometer at room temperature beginning at 5minutes.

For Examples 9 and 10, a prehydrated HPG mixture was first prepared from100 g DI water, 0.025 ml 50% aqueous solution of alkyl (C₁₂-C₁₆)dimethyl benzyl ammonium chloride, 10 g PEG 10K, and 4 g HPG. In Example9, the HPG had 0.6 molar substitution, JAGUAR HP-60; and in Example 10,HPG with 0.4 molar substitution, ECOPOL 400DS, was used. These solutionswere stirred until complete dissolution of the components created apre-hydrated concentrate. Approximately 17 g of pre-hydrated concentratewas then added to 100 ml of the 1.318 g/mL (11.0 ppg) CaCl₂ brine tocreate a solution containing 0.5 wt % HPG in the brine. Mixing times andmeasurements were otherwise done in the same way as for the dry guar inExamples 7 and 8.

FIG. 6 compares the viscosity development of the two HPG guars injectedinto brine as dry and pre-hydrated concentrates. Each of thepre-hydrated concentrate formulations in Examples 9 and 10 generatedviscosity rapidly and showed appreciable viscosification within 5minutes of initial mixing. In contrast, addition of dry HPG to the brinein Examples 7 and 8 showed very little viscosity development after fiveminutes, and even after 30 minutes. In fact, after 30 minutes theviscosity of the dry guar formulations was an order of magnitude lessthan the viscosity of the formulations mixed from aqueous concentrates.An advantage of the prehydrated embodiments of Examples 9 and 10 is thatthe pre-hydrated concentrates rapidly viscosity heavy brines thatotherwise would require the use of slow polymer hydration processes.Pre-hydration yields significant viscosity within 5 min, while directhydration of dry guar into the brine may not yield significant viscosityeven after 30 minutes.

Examples 11-16

Test procedure for determining percent hydration vs. rpm. In a WARINGblender equipped with a tachometer to read the blender blade rotationalspeed, 500 mL of water were charged. Using the variable power setting,the rpm were set to a level to create a deep vortex but not so deep asto entrap too much air, which was determined to be in the range ofbetween 1500-1600 rpm, and this setting was used throughout thefollowing examples. Dry rheological polymer such as guar with a size <40mesh (Example 11) was then added to the blender all at once, and as thepolymer hydrated, the fluid became viscous and harder to stir, and therpm of the blender decreased, as shown in FIG. 7. These data were thanused to derive from the rpm change a hydration curve as the percenthydration of the polymer as a function of time, as shown in FIG. 8.

For Example 12, this hydration procedure was repeated with the sameamount of polymer in the form of a water-in-water emulsion which wasfirst prepared separately in a WARING blender based on composition 30 inFIG. 2 and Example 2 described above, i.e. a mixture of 10% polymer and6% PEG 8000. For a dilution of 20:1 in the 500 ml water charged to theblender, 25 ml of the concentrate was added at t=0.

For Examples 13 and 14, the water-in-water emulsion of composition 30was processed with a SILVERSON high shear mixer for 10 minutes and 20minutes, respectively. For Example 15, the guar concentrate ofcomposition 30 was processed by wet grinding with an electric mortar for10 minutes. These processed water-in-water emulsion samples were thenused to develop hydration curves using the procedure of Example 12. FIG.9 shows the hydration curves for Examples 11-15. As indicated, thehydration rate of the base water-in-water emulsion (Example 12) wasequivalent to or improved slightly over the dry polymer (Example 11).Grinding or shearing the water-in-water emulsion with either ahigh-shear mixer (Examples 13-14) or an electric mortar (Example 15)resulted in faster hydration.

For Example 16, the guar concentrate of composition 30 was heated to65.6° C. (150° F.) just before addition to the room temperature water(500 ml) in the blender. FIG. 7 shows the improvement on hydration ofExample 16 achieved by heating the water-in-water emulsion before thehydration test, compared to the base emulsion without preheating(Example 12). Note the heating was with a highly concentrated slurry,which accounted for about 5 wt % of the total final hydrated gel, i.e. a95% reduction in heating requirements compared to heating the entiremixture of the pre-gel components.

Example 17

Wellsite hydration process using water-in-water emulsion. FIG. 11 showsan example of a flow diagram for equipment to implement a hydrationprocess 100 using water-in-water emulsion technique. Dry guar 102 andPEG 8000 104, which can be a dry powder, aqueous solution or slurry, aresupplied together with a first stream 106 of water 108 to mixing zone110, which can be an inline, batch or continuous mixer for mixingliquids and solids. The water-in-water emulsion can be optionally storedin an emulsion holding tank 112. The emulsion is then processed ingrinding zone 114 and/or heating zone 116 for prehydration enhancement.This allows efficient energy use to process a relatively small stream,where one of the previously infeasible approaches to hydrate guar areused, for example, high shear, heating, or ultrasonic vibration (notshown). The processed emulsion is then supplied to dilution zone 118where it is diluted with second water stream 120 to form the gel whichis then received in optional header tank 122 and with sufficientresidence time in the line 124 and/or tank 122 for complete hydration,supplied to an otherwise conventional POD metering system operativelyassociated with additive pumps 128 and wellhead 130. The ratio of thefirst water stream 106 to the second water stream 120 is about 1:20 inone embodiment.

Examples 18-19

Polyacrylamide friction reducer concentrates. A solution was made byadding 2% by weight KCL to distilled water. For Example 18, 7.5 weightpercent of 7000 molecular weight polyethylene glycol was then added tothe KCl solution. Then 20% by weight of high molecular weightpolyacrylamide was added to the solution. The solution was stirred. Theresulting mixture had water like viscosity. For Example 19, 7.5 weightpercent of BRIJ 38 polyoxyethylene was added to the 7.5 wt % KClsolution, followed by 20% by weight of the high molecular weightpolyacrylamide was added to the solution. The solution was stirred andthe resulting mixture again had water like viscosity.

The particular embodiments disclosed above are illustrative only, as theinvention may be modified and practiced in different but equivalentmanners apparent to those skilled in the art having the benefit of theteachings herein. Furthermore, no limitations are intended to thedetails herein shown, other than as described in the claims below. It istherefore evident that the particular embodiments disclosed above may bealtered or modified and all such variations are considered within thescope and spirit of the invention. Accordingly, the protection soughtherein is as set forth in the claims below.

1-25. (canceled)
 26. A method comprising: a. mixing a rheologicalpolymer, a partitioning agent and a first aqueous medium to form aheterogeneous mixture comprising a dispersed rheological polymer-richphase and a partitioning agent-rich phase; and, b. diluting theheterogeneous mixture with a second aqueous medium miscible with thefirst aqueous medium to mutually dissolve the polymer-rich phase and thepartitioning-agent rich phase and form a fluid comprising a continuousmixed polymer-agent phase.
 27. The method of claim 26 wherein thecontinuous mixed polymer-agent phase has an apparent viscosity at 1 l/sand 25° C. that is greater than the bulk apparent viscosity of theheterogeneous mixture.
 28. The method of claim 26 wherein the mixingstep comprises at least partially hydrating the rheological polymer. 29.The method of claim 26 wherein the partitioning agent-rich phase iscontinuous and the rheological polymer-rich phase is finely dispersedtherein.
 30. The method of claim 26 wherein the partitioning agentcomprises a water soluble polymer.
 31. The method of claim 26 whereinthe mixing step comprises a weight ratio of the rheological polymer tothe partitioning agent from 1:4 to 4:1.
 32. The method of claim 26wherein the continuous mixed polymer-agent phase comprises from 0.01 to1 percent by weight rheological polymer based on the weight of theliquid media.
 33. The method of claim 26 wherein the heterogeneousmixture comprises from 2 to 20 percent by weight rheological polymerbased on the weight of the aqueous media in the heterogeneous mixture.34. The method of claim 26 wherein the partitioning agent comprises apolymer soluble in the first liquid aqueous and having a solubilitydifferent with respect to the rheological polymer.
 35. The method ofclaim 26 wherein concentrated solutions of the rheological polymer andof the partitioning agent in the first aqueous medium are immiscible.36. The method of claim 26 wherein the rheological polymer comprisespolysaccharide.
 37. The method of claim 26 wherein the partitioningagent comprises polyalkylene oxide.
 38. The method of claim 26 whereinthe heterogeneous mixture comprises polyethylene glycol and one or moreof guar, guar derivative, cellulose, cellulose derivative,heteropolysaccharide, heteropolysaccharide derivative, or polyacrylamidein an aqueous medium.
 39. The method of claim 26 wherein the secondaqueous medium comprises high density brine.
 40. The method of claim 26further comprising mechanically, thermally or mechanically and thermallyprocessing the heterogeneous mixture effective to increase a rate ofhydration of the rheological polymer in the dilution step.
 41. Themethod of claim 26 further comprising processing the heterogeneousmixture to increase a rate of rheological polymer dissolution in thedilution step, wherein the processing is selected from the groupconsisting of high shear mixing, wet grinding, ultrasonification,heating and a combination thereof.
 42. The method of claim 26 whereinthe partitioning agent comprises nonionic surfactant.
 43. The method ofclaim 26 further comprising dispersing a gas phase in the fluid to forman energized fluid or foam.
 44. A method comprising: a. mixingpolyethylene glycol partitioning agent and one or more rheologicalpolymers selected from the group consisting of guar, modified guar,cellulose, modified cellulose, heteropolysaccharide,heteropolysaccharide derivative, or polyacrylamide, with a first aqueousmedium to hydrate the one or more polymers and form a water-in-wateremulsion; and b. mixing the water-in-water emulsion with a secondaqueous medium to form a well treatment fluid; c. injecting the fluidinto a well bore and treating a subterranean formation.
 45. Aconcentrated viscosifying additive for preparing a fluid comprising apumpable water-in-water emulsion of polyethylene glycol, and one or morerheological polymers selected from the group consisting of guar,modified guar, cellulose, modified cellulose, heteropolysaccharide,heteropolysaccharide derivative, or polyacrylamide.